Institution of Gas Engineers & Managers

The usage of fossil fuels to generate energy and the lack of wastewater treatment in Mexico are two issues that can be addressed at the same time while developing wastewater treatment technologies that incorporate energy recovery in their process train. We carried out a systematic review based on the PRISMA methodology to identify and review studies regarding energy recovery using wastewater as a substrate in Mexico. Peer-reviewed papers were identified through Scopus Web of Knowledge and Google Scholar using a timeframe of 22 years that represented from 2000 to 2022. After applying the selection criteria we identified 31 studies to be included in the final review starting from 2007. The kind of energy product type of technology used substrate wastewater amount of energy produced and main parameters for the operation of the technology were extracted from the papers. The results show that methane is the most researched energy recovery product from wastewater followed by hydrogen and electricity and the technology used to archive it is an up-flow anaerobic sludge bed (UASB) reactor to produce methane and hydrogen. In addition microbial fuel cells (MFCs) were preferred to produce electricity. According to our data more energy per kgCOD removed could be obtained with methane-recovering technologies in the Mexican peer-reviewed studies compared with hydrogen recovery and electricity production.

In this Podcast David Ledesma discusses with Stephen Craen Visiting Research Fellow OIES the challenges facing the financing of future hydrogen projects as it is expected that a substantial amount of capital will need to be invested in green hydrogen production to meet the 2050 net zero targets. Based around an ‘Archetype’ world scale hydrogen export project where 1 GW solar power is used to make green hydrogen which is converted to 250000 tpa green ammonia for export with a capital cost in the region of USD 2 billion the podcast discusses how ‘efficient financing’ can make an important contribution to minimising cost and making projects cost competitive. Stephen Craen argues that lenders and investors will look to precedents when assessing the nascent green hydrogen sector and the foremost will be LNG and offshore wind which both represent large-scale technically complex projects. Commercial structures of the green hydrogen business are expected to borrow concepts from offshore wind projects particularly in relation to price but also from LNG where this is relevant such as take-or-pay contracts. In this podcast we discuss the key issues that will need to be addressed to make a green hydrogen export project bankable concluding that commercial debt from either commercial banks or project bonds can help create competition.

The podcast can be found on their website.

In this study we present a pre-feasibility analysis that examines the viability of implementing autonomous green hydrogen production plants in two strategic regions of Chile. With abundant renewable energy resources and growing interest in decarbonization in Chile this study aims to provide a comprehensive financial analysis from the perspective of project initiators. The assessment includes determining the optimal sizing of an alkaline electrolyzer stack seawater desalination system and solar and wind renewable energy farms and the focus is on conducting a comprehensive financial analysis from the perspective of project initiators to assess project profitability using key economic indicators such as net present value (NPV). The analyses involve determining appropriate sizing of an alkaline electrolyzer stack a seawater desalination system and solar and wind renewable energy farms. Assuming a base case production of 1 kiloton per year of hydrogen the capital expenditures (CAPEX) and operating expenses (OPEX) are determined. Then the manufacturing and production costs per kilogram of green hydrogen are calculated resulting in values of USD 3.53 kg−1 (utilizing wind energy) and USD 5.29 kg−1 (utilizing photovoltaic solar energy). Cash flows are established by adjusting the sale price of hydrogen to achieve a minimum expected return on investment of 4% per year yielding minimum prices of USD 7.84 kg−1 (with wind energy) and USD 11.10 kg−1 (with photovoltaic solar energy). Additionally a sensitivity analysis is conducted to assess the impact of variations in investment and operational costs. This research provides valuable insights into the financial feasibility of green hydrogen production in Chile contributing to understanding renewable energy-based hydrogen projects and their potential economic benefits. These results can provide a reference for future investment decisions and the global development of green hydrogen production plants.

The National Hydrogen Strategy sets out the strategic vision on the role that hydrogen will play in Ireland’s energy system looking to its long-term role as a key component of a zero-carbon economy and the short-term actions that need to be delivered over the coming years to enable the development of the hydrogen sector in Ireland.<br/>The Strategy is being developed for three primary reasons:<br/>1. Decarbonising our economy providing a solution to hard to decarbonise sectors where electrification is not feasible or cost-effective<br/>2. Enhancing our energy security through the development of an indigenous zero carbon renewable fuel which can act as an alternative to the 77% of our energy system which today relies on fossil fuel imports<br/>3. Developing industrial opportunities through the potential development of export markets for renewable hydrogen and other areas such as Sustainable Aviation Fuels<br/>The Strategy considers the needs of the entire hydrogen value chain including production end-uses transportation and storage safety regulation markets innovation and skills.<br/>It also sets out that Ireland will focus its efforts on the scale up and production of renewable ""green"" hydrogen as it supports both our decarbonisation needs and energy security needs given our vast indigenous renewable resources. Renewable hydrogen is a renewable and zero-carbon fuel that can play a key role in the ""difficult-to-decarbonise"" sectors of our economy where other solutions such as direct electrification are not feasible or cost effective.<br/>In the coming years renewable hydrogen is envisioned to play an important role as a zero-emission source of dispatchable flexible electricity as a long duration store of renewable energy in decarbonising industrial processes and as a transport fuel in sectors such as heavy goods transport maritime and aviation. The Strategy will provide clarity for stakeholders on how we expect the hydrogen economy to develop and scale up over the coming decades across the entire value chain.

In this paper by using a large eddy simulation we study the combustion process in the HyShot II scramjet combustor. By conducting a detailed analysis of the mass-fraction distributions of the main species such as H2 H2O and the radicals OH and HO2 of the mass source terms of these main species and of the chemical source term of the energy equation we detect the regions where chemical reactions occur through a diffusion process and the regions where auto-ignition and premixed combustion may develop. The analysis indicates that the combustion process is mainly of diffusive type along a thin shear layer enveloping the hydrogen plume whereas there could be some auto-ignition and/or premixed combustion cores inside the plume.

Hybrid renewable hydrogen energy systems could play a key role in delivering sustainable solutions for enabling the Net Zero ambition; however the lack of exact computational modelling tools for sizing the integrated system components and simulating their real-world dynamic behaviour remains a key technical challenge against their widespread adoption. This paper addresses this challenge by developing a precise dynamic model that allows sizing the rated capacity of the hybrid system components and accurately simulating their real-world dynamic behaviour while considering effective energy management between the grid-integrated system components to ensure that the maximum possible proportion of energy demand is supplied from clean sources rather than the grid. The proposed hybrid system components involve a solar PV system electrolyser pressurised hydrogen storage tank and fuel cell. The developed hybrid system model incorporates a set of mathematical models for the individual system components. The developed precise dynamic model allows identifying the electrolyser’s real-world hydrogen production levels in response to the input intermittent solar energy production while also simulating the electrochemical behaviour of the fuel cell and precisely quantifying its real-world output power and hydrogen consumption in response to load demand variations. Using a university campus case study building in Scotland the effectiveness of the developed model has been assessed by benchmarking comparison between its results versus those obtained from a generic model in which the electrochemical characteristics of the electrolyser and fuel cell systems were not taken into consideration. Results from this comparison have demonstrated the potential of the developed model in simulating the real-world dynamic operation of hybrid solar hydrogen energy systems for grid-connected buildings while sizing the exact capacity of system components avoiding oversizing associated with underutilisation costs and inaccurate simulation.

The glass industry is part of the energy-intensive industry with most of the energy needed to melt the raw materials. To produce glass temperatures between 1000 and 1600 °C are necessary. Presently mostly fossil natural gas is the dominant energy source. As direct electrification is not always possible in this paper a Life Cycle Assessment (LCA) for specialty glass production is conducted where the conventional fossil-based reference process is compared to a hydrogen-fired furnace. This hydrogen can be produced on-site in an water electrolyzer using not only the hydrogen for the combustion but also the produced oxygen. Hydrogen can be produced alternatively off-site in a large scale electrolyzer to facilitate economy of scale. For the transport and distribution of this hydrogen different options are available. A rather new option are liquid organic hydrogen carriers (LOHC) which bind the hydrogen in a chemical substance. However temperatures around 300 °C are necessary to separate the hydrogen from the LOHC after transport. At the glass trough waste heat is available at the required temperature level to facilitate the dehydrogenation. The comparison is completed by the production of off-site hydrogen transported to the glass trough as conventional liquefied hydrogen in cooling tanks by truck or in hydrogen pipelines. In this assessment to power the electrolyzers the national grid mix of Germany is used. A time frame from 2020 till 2050 and its changing energy system towards defossilisation is analyzed. Regarding climate change on-site hydrogen production causes the least impact for specialty glass production in 2050. However negative trade-offs for other environmental impact categories e.g. Metal depletion are recorded.

Green hydrogen is a key element that has the potential to play a critical role in the global pursuit of a resilient and sustainable future. However like other energy production methods hydrogen comes with challenges including high costs and safety concerns across its entire value chain. To overcome these low-cost productions are required along with a promised market. Offshore renewables have an enormous potential to facilitate green hydrogen production on a large scale. Their plummeting cost technological advances and rising cost of carbon pave a pathway where green hydrogen can be cost-competitive against fossil-fuel-based hydrogen. Offshore industries including oil and gas aquaculture and shipping are looking for cleaner energy solutions to decarbonize their systems/operations and can serve as a substantial market. Offshore industrial nexus moreover can assist the production storage and transmission of green hydrogen through infrastructure sharing and logistical support. The development of offshore green hydrogen production facilities is in its infancy and requires a deeper insight into the key elements that govern decision-making during their life-cycle. This includes the parameters that reflect the performance of hydrogen technology with technical socio-political financial and environmental considerations. Therefore this study provides critical insight into the influential factors discovered through a comprehensive analysis that governs the development of an offshore green hydrogen system. Insights are also fed into the requirements for modelling and analysis of these factors considering the synergy of hydrogen production with the offshore industries coastal hydrogen hub and onshore energy demand. The results of this critical review will assist the researchers and developers in establishing and executing an effective framework for offshore site selection in largely uncertain and hazardous ocean environments. Overall the study will facilitate the stakeholders and researchers in developing decision-making tools to ensure sustainable and safe offshore green hydrogen facilities.

This current article discusses the technoeconomics (TE) of hydrogen generation transportation compression and storage in the Australian context. The TE analysis is important and a prerequisite for investment decisions. This study selected the Australian context due to its huge potential in green hydrogen but the modelling is applicable to other parts of the world adjusting the price of electricity and other utilities. The hydrogen generation using the most mature alkaline electrolysis (AEL) technique was selected in the current study. The results show that increasing temperature from 50 to 90 ◦C and decreasing pressure from 13 to 5 bar help improve electrolyser performance though pressure has a minor effect. The selected range for performance parameters was based on the fundamental behaviour of water electrolysers supported with literature. The levelised cost of hydrogen (LCH2 ) was calculated for generation compression transportation and storage. However the majority of the LCH2 was for generation which was calculated based on CAPEX OPEX capital recovery factor hydrogen production rate and capacity factor. The LCH2 in 2023 was calculated to be 9.6 USD/kgH2 using a base-case solar electricity price of 65–38 USD/MWh. This LCH2 is expected to decrease to 6.5 and 3.4 USD/kgH2 by 2030 and 2040 respectively. The current LCH2 using wind energy was calculated to be 1.9 USD/kgH2 lower than that of solar-based electricity. The LCH2 using standalone wind electricity was calculated to be USD 5.3 and USD 2.9 in 2030 and 2040 respectively. The LCH2 predicted using a solar and wind mix (SWM) was estimated to be USD 3.2 compared to USD 9.6 and USD 7.7 using standalone solar and wind. The LCH2 under the best case was predicted to be USD 3.9 and USD 2.1 compared to USD 6.5 and USD 3.4 under base-case solar PV in 2030 and 2040 respectively. The best case SWM offers 33% lower LCH2 in 2023 which leads to 37% 39% and 42% lower LCH2 in 2030 2040 and 2050 respectively. The current results are overpredicted especially compared with CSIRO Australia due to the higher assumption of the renewable electricity price. Currently over two-thirds of the cost for the LCH2 is due to the price of electricity (i.e. wind and solar). Modelling suggests an overall reduction in the capital cost of AEL plants by about 50% in the 2030s. Due to the lower capacity factor (effective energy generation over maximum output) of renewable energy especially for solar plants a combined wind- and solar-based electrolysis plant was recommended which can increase the capacity factor by at least 33%. Results also suggest that besides generation at least an additional 1.5 USD/kgH2 for compression transportation and storage is required.

The steel sector currently accounts for 7% of global energy-related CO2 emissions and requires deep reform to disconnect from fossil fuels. Here we investigate the market competitiveness of one of the widely considered decarbonisation routes for primary steel production: green hydrogen-based direct reduction of iron ore followed by electric arc furnace steelmaking. Through analysing over 300 locations by combined use of optimisation and machine learning we show that competitive renewables-based steel production is located nearby the tropic of Capricorn and Cancer characterised by superior solar with supplementary onshore wind in addition to high-quality iron ore and low steelworker wages. If coking coal prices remain high fossil-free steel could attain competitiveness in favourable locations from 2030 further improving towards 2050. Large-scale implementation requires attention to the abundance of suitable iron ore and other resources such as land and water technical challenges associated with direct reduction and future supply chain configuration.